Oil in virtually all reservoirs contains dissolved gases which originate internally within the oil. During oil production, oil flows from the formation towards the wellbore which results in two critical phenomena. First, the oil reaching the wellbore is at a lower pressure relative to oil in the formation. This pressure depletion leads to the evolution of dissolved gases which causes bubbles to form in the oil. The presence of these dispersed bubbles increases the effective viscosity of the oil. The viscosity effect is particularly pronounced in reservoirs of heavy oils. Although the amount of dissolved gas may not be large, the effect can be significant because of the high stability of the foam and its ability to build up over time. By way of comparison, at atmospheric pressure, a heavy oil sample is capable of sustaining bubbles (e.g., foams) of free gas in solution as long as 4 to 5 hours before the gas is liberated. In contrast, free gas may be liberated from light oil in less than 1 minute. Furthermore, in heavy oil, some of the evolved gas in the form of bubbles (or foams) may be immobile, that is, the gas cannot flow to the wellbore or migrate upward in the formation; rather, the viscous oil accumulates around the wellbore. This phenomenon has been observed in low gravity oil (below 20.degree. API) reservoirs, such as shallow San Joaquin Valley fields in California with a depth of less than 1,500 feet.
The second phenomenon associated with the flow of oil towards the wellbore is that the velocity of the oil reaching the wellbore is higher than the oil velocity at other parts of the reservoir. If water is present in the vicinity of the wellbore, the attendant mixing of the immiscible oil and water caused by the velocity increase results in the formation of emulsions that are stabilized by fine particles or asphaltenes from the crude oil. These are generally oil external emulsions which have higher viscosities than either oil or water in the formation. The effective viscosity is determined principally by the amount of water dispersed in the oil. The water may be connate and/or water from steam injection. Both phenomena generally occur at the same time, that is, the oil viscosity is enhanced by the presence of both the gas bubbles and dispersed water droplets.
Cyclic or continuous steam injection is the preferred thermal process for recovering heavy oils. Steam is injected from one or more injection wells located in the vicinity of the production wellbore. The heat released from the condensing steam reduces the oil viscosity and improves its mobility through the formation during production. However, introduction of a foreign fluid (e.g., wet steam) into the reservoir enhances emulsification of oil and water. In addition, this viscous emulsion also appears to stabilize the foams. As is apparent, the presence of the foamy emulsion near the wellbore can drastically reduce well production by interfering with oil flow into the wellbore. Furthermore, foam which enters inside the casing of the wellbore also reduces pumping efficiency and increases wear.
One approach to stimulating well production as described in U.S. Pat. No. 3,481,404 to Gidley involves injecting an acid solution into the wellbore followed by an afterflush that consists of a hydrocarbon oil and a solvent miscible with oil and water. Diesel fuels are the preferred hydrocarbon oil and glycol ethers such as ethylene glycol monobutyl ether are preferred solvents. While this technique has been successful in some reservoirs where emulsion formation near the wellbore is minimum, this process is not particularly applicable to heavy oil reservoirs where steam injection is also employed.
Accordingly, this invention is directed to improving the mobility of oil in a reservoir formation, especially in and near the wellbore by suppressing or extinguishing foams and emulsions and by increasing the oil relative permeability in the near wellbore region.